Conventional oil and gas recovery involves drilling a well and then pumping a mixture of oil and water from the well. Oil is separated from the water, and the produced water is usually re-injected into a sub-surface formation. Conventional oil recovery works well for low viscosity oil. However, conventional oil recovery processes do not work well for higher viscosity oil, also referred to as heavy oil. Conventional oil recovery processes also do not work well for oil or gas trapped in low permeability rock formations.
There are several methods used for enhanced recovery of oil (“EOR”) and gas (“EGR”). Several of them involve injecting water, either in the form of steam or as a liquid, and in some cases with additives, to promote recovery of oil and gas. All of the water based methods generate produced water, which flows to the surface along with the hydrocarbons. Treating produced water, or treating the by-products of produced water treatment, to allow reuse or deep well disposal of the water poses a challenge when the water contains dissolved colloidal organics or sparingly soluble inorganic constituents.
The injection of steam into heavy oil bearing formations is a widely practiced EOR method. Typically, several tonnes of steam are required for each tonne of oil recovered. Steam heats the oil in the reservoir, which reduces the viscosity of the oil and allows the oil to flow to a collection well. The steam condenses and mixes with the oil and with any naturally occurring water in the formation. The mixture of condensed steam and naturally occurring water becomes produced water. The mixture of oil and produced water that flows to the collection well is pumped to the surface. Oil is separated from the produced water by conventional processes employed in conventional oil recovery operations.
For economic and environmental reasons it is desirable to recycle the produced water used in steam injection EOR. This is accomplished by treating the produced water, producing a feedwater, and directing the treated feedwater to a steam generator or boiler. The complete water cycle includes the steps of:                a. injecting the steam into an oil bearing formation,        b. condensing the steam to heat the oil whereupon the condensed steam mixes with the oil to become produced water,        c. collecting the oil and produced water in a well,        d. pumping the mixture of oil and produced water to the surface,        e. separating the oil from the produced water,        f. treating the produced water so that it becomes the steam generator or boiler feedwater, and        g. converting 70% to 95% of the feedwater into steam for injecting into the oil bearing formation.        
Treating the produced water to form a relatively pure boiler feed water for steam generation is challenging and generates waste streams containing dissolved organics and other sparingly soluble constituents which are difficult to further reuse or to dispose of in a deep well.
It is known that chemically treating water to precipitate the silica reduces the silica concentration to a level that is suitable for a Once Through Steam Generator (“OTSG”). This process is generally referred to as Warm Lime Softening followed by Ion Exchange (WLS/IX). The silica precipitates in a calcium carbonate/magnesium hydroxide sludge that is created by addition of lime, soda ash, and magnesium hydroxide. However, the WLS/IX process removes only a small portion of the organics and virtually none of the dissolved salts. Proper performance of the OTSG requires a blowdown stream of 10% to 30% of the feed water to prevent fouling or scaling of the heat transfer surface from the organics and salts. This blowdown stream is often further concentrated in an evaporator to recover water. The blowdown stream from the evaporator has a pH greater than 11, and contains 5,000 to 20,000 ppm of Total Organic Carbon (TOC) and more than 200 ppm of silica. The blowdown stream, if injected directly into a deep well, has the potential to plug the formation due to downhole precipitation of silica.
It is also known to chemically treat the produced water and subject the produced water to an evaporation process to form distillate for steam generation feedwater. In particular, it is known to use an evaporator and mechanical vapor compressor to produce the distillate. The pH of the feed to the evaporator is raised to maintain the solubility of silica. This prevents silica based scales from fouling the evaporator heat transfer surface. However, there are drawbacks and disadvantages to the current processes. The mechanical vapor compression evaporator recovers approximately 95% of the water from the de-oiled produced water. The remaining 5% of the produced water stream is difficult to process. The pH of the resultant stream is usually higher than 12, which makes the stream hazardous. Any attempt to neutralize the stream causes the precipitation of silica solids and organic compounds which are very difficult to separate from the aqueous solution. The neutralization process is also known to release hazardous gases, like hydrogen sulfide.
It is known that oil recovery gradually declines from conventional oil reservoirs using primary production and as little as 10% to 15% of the oil in place will be recovered. Secondary recovery using water flooding can improve oil recovery and allow recovery of an additional 10% to 15% of the oil in place. The injection of water with additives further improves recovery is also a widely practiced EOR. The additives may be alkaline surfactant polymer (ASP) for low pressure applications in conventional reservoirs. The produced water from primary and secondary recovery can be treated using conventional oil water separation techniques and then reused or disposed. The produced water from tertiary recovery using ASP is challenging to treat and reuse due to the presence of residual ASP polymer and ASP polymer degradation products. Various technologies have been tried, including conventional chemical precipitation, electrocoagulation, and membrane separation. These technologies have been only partially successful and generate wastes which are difficult to dewater and dispose or that do not sufficiently remove contaminants to meet the requirements for deep well disposal.
It is also known that injecting water with additives, known as hydraulic fracturing fluid, and sand into certain shale formations at sufficient pressure to fracture the rock releases trapped oil and/or gas. The additives may be gel type polymers intended to suspend sand particles in hydraulic fracturing operations. The volume of hydraulic fracturing fluid used in each well varies from several thousand cubic meters to several hundred thousand cubic meters. The sand is forced into the cracks of the shale formation to prop them open. After the pressure is reduced a portion of the injected water with additives flows from the well and then the previously trapped oil and/or gas flows into the well. The volume of flowback water varies from 5% to 75% of the initially injected volume of the hydraulic fracturing fluid. The flowback water can be reused or must be disposed. It is known that water with gel type polymer is more efficient at holding sand in suspension and delivering the sand into the cracks. However, flowback water with gel type polymer is difficult to treat for reuse or disposal. As with produced water from ASP floods, various technologies have been tried and have been only partially successful and generate wastes which are difficult to dewater and dispose.